Q3 Report for the NINE MONTHS ENDED 30 September 2021 (org number: 559018‐9543)

Highlights

(all amounts are in US dollars unless otherwise noted)

Third Quarter 2021

Daily oil & gas production for Q3 2021 averaged 3,610 BOEPD (Q3 2020: 3,580 BOEPD)
Revenue of USD 19.5 million (Q3 2020: USD 11.2 million)
Operating netback of USD 13.6 million or USD 41.17 per BOE (Q3 2020: USD 7.0 million or USD 21.12 per BOE)
EBITDA of USD 12.9 million (Q3 2020: USD 5.5 million)
Net result of USD 6.1 million (Q3 2020: USD 1.8 million)
Basic Earnings per share of USD 0.05 (Q3 2020: USD 0.02)
Diluted Earnings per share of USD 0.05 (Q3 2020: USD 0.02)
Cash and cash equivalents balance of USD 31.8 million (Q3 2020: 18.0 million)

Nine months Ended 30 September 2021

Daily oil & gas production for nine months 2021 averaged 3,485 BOEPD (Nine months 2020: 3,490 BOEPD)
Revenue of USD 50.5 million (Nine months 2020: USD 30.4 million)
Operating netback of USD 34.1 million or USD 36.92 per BOE (Nine months 2020: USD 19.3 million or USD 20.67 per BOE)
EBITDA of USD 32.1 million (Nine months 2020: USD 15.4 million)
Net result for the period of USD 14.2 million (Nine months 2020: USD 5.4 million)
Basic Earnings per share of USD 0.13 (Nine months 2020: USD 0.05)
Diluted Earnings per share of USD 0.13 (Nine months 2020: USD 0.05)
Cash and cash equivalents balance of USD 31.8 million (2020: USD 6.7 million)

						Nine	Nine
	Q3	Q2	Q1	Q4	Q3	months	months	FY
(TUSD, unless otherwise noted)	2021	2021	2021	2020	2020	2021	2020	2020
Net Daily Production (BOEPD)	3,610	3,104	3,742	2,738	3,580	3,485	3,490	3,301
Revenue	19,496	15,178	15,814	8,659	11,226	50,488	30,359	39,018
Operating netback	13,568	9,548	11,031	4,247	7,041	34,147	19,276	23,523
EBITDA	12,909	8,988	10,213	2,720	5,514	32,110	15,384	18,104
Net result for the period1	6,083	2,603	5,538	(15,702)	1,845	14,224	5,443	(10,259)
Earnings per share – Basic (USD)	0.05	0.02	0.05	(0.15)	0.02	0.13	0.05	(0.10)
Earnings per share – Diluted (USD)	0.05	0.02	0.05	(0.15)	0.02	0.13	0.05	(0.10)
Cash and cash equivalents	31,778	34,139	5,698	6,681	18,034	31,778	18,034	6,681

Financial Summary

¹ Net result of Q4 2020 and full year 2020 includes an impairment charge of USD 21.0 million.

Definitions

SEK	Swedish Krona	BBL or bbl	Barrel

USD	US Dollar	BOPD	Barrels of Oil Per Day
TSEK	Thousand SEK	Mbbl	Thousand barrels of Oil
TUSD	Thousand USD	MMbbl	Million barrels of Oil

Abbreviations Oil related terms and measurements

CAD	Canadian Dollar	BOE or boe	Barrels of Oil Equivalents
SEK	Swedish Krona	BBL or bbl	Barrel
BRL	Brazilian Real	BOEPD	Barrels of Oil Equivalents Per Day
USD	US Dollar	BOPD	Barrels of Oil Per Day
TSEK	Thousand SEK	Mbbl	Thousand barrels of Oil
TUSD	Thousand USD	MMbbl	Million barrels of Oil
MSEK	Million SEK	Mboe	Thousand barrels of oil equivalents
MUSD	Million USD	MMBoe	Millions of barrels of oil equivalents
		Mboepd	Thousand barrels of oil equivalents per day
		Mbopd	Thousand barrels of oil per day
		MCF	Thousand Cubic Feet
		MSCFPD	Thousand Standard Cubic Feet per day
		MMSCF	Million Standard Cubic Feet
		MMSCFPD	Million Standard Cubic Feet Per Day
		BWPD	Barrels of Water Per Day

Gas to oil conversion

6,000 cubic feet = 1 barrel of oil equivalent

Letter to shareholders

Dear Friends and Fellow Shareholders of Maha Energy AB,

By now, I was really hoping that we could have announced some promising results from our first horizontal well on the Tie field, but alas, that is unfortunately not the case. The Tie‐4 well continues to test us and we are currently re‐ drilling the 8‐1/2" production hole, for the third time. As an old 'Driller' I can tell you how gut wrenching it is when you stick the drillstring in the hole. Fishing and sidetracking operations are time consuming and expensive. To add insult to injury the delay in completion are deferring profitable barrels that would have added to our healthy bottom line this quarter, especially at the current price of oil.

Having said that, we are delivering a record quarter in terms of revenue and EBITDA. The net result for the period is not far behind and would have also broken our previous record had we not incurred extra costs when completing the successful acid stimulation of Tie 3 (increased rate from ~100 to 240 bopd) and some slickline work on GTE‐4 during the quarter. Our netbacks are very healthy at USD 41.17/BOE and our net result is USD 6.083 million for the quarter.

Our production for the quarter was impacted by the problems on Tie‐4, but the other wells are actually performing better than predicted ‐ so I am bullish on our future production provided we can get our horizontal wells drilled on time. To that extent, we have taken a number of concrete steps to address the continuing drilling problems that are plaguing us and we are stubbornly working through all the issues.

In Oman we are gathering momentum. The Covid induced supply chain problems we are experiencing are challenging our crew in Oman, but I am pleased to say that we have located and ordered all critical long lead items for the wells in Oman and we are currently sourcing a drilling rig. I am hopeful to start drilling in Oman during the first half of next year.

In the USA, production at our Illinois Basin (IB) property is ramping up. We have had some excellent drilling results this year and all wells are now completed, stimulated and hooked up to pumps. Five of the new wells are already producing good quantities of oil, one more is just breaking to oil from water and five are still being dewatered from stimulation fluids. We expect that IB will be in full oil production by the end of the year. Last week's oil production from IB is averaging 287 BOPD.

I know that the recent downward revision in our estimated annual average production rate was very disappointing. We share that disappointment and I know I speak for all Maha employees when I say that no one is working harder than our drilling team to get the wells drilled and placed on production as soon as possible. This is the oil business and we are working hard and as fast as we can to create redundancy in our production portfolio so that we are less dependent on our Tie field. That is why it was important to diversify into IB and Oman during 2020. I am confident that as we end 2021 and look into 2022 we can look forward to more wells and more oil!

I am grateful of the support we are getting from our shareholders and we value your continued support. No doubt, we will achieve our goals ‐ the oil is there and it has been there for millions of years, it just has to wait a few more months until it sees daylight

As always, a big thank you to all Maha employees that I know work so hard for all of us. And to all fellow shareholders – thank you for your continued support.

Yours truly,

"Jonas Lindvall" Managing Director

Financial Report for the Third Quarter ended 30 September 2021

OPERATIONAL AND FINANCIAL REVIEW

Strategy

The Company's business activities include the exploration for and the development and production of hydrocarbons. The Company's core expertise is in primary, secondary and enhanced oil and gas recovery technologies and, as such, its business strategy is to target and develop underperforming hydrocarbon assets. By focusing on assets with proven hydrocarbon presence and applying modern and tailored technology solutions to recover the hydrocarbons in place, the Company's primary risk is not uncertainty in reservoir content but in the fluid extraction.

Assets

Country	Concession name	Maha Working Interest (%)	Status	Net Area (acres)	BOEPD (2 )	Partner
Oman	Block 70	100%	Pre‐Production	157,900	‐	‐
USA	LAK Ranch	99%	Pre‐Production	6,475	‐	SEC (1%)
USA	Il Basin (various)	100%	Producing	3,134	223
Brazil	Tartaruga	75%	Producing	5,944	182	Petrobras (25%)
Brazil	Tie (REC‐T 155)	100%	Producing	1,511	3,202
Brazil	REC‐T 155	100%	Exploration	4,276	‐
Brazil	REC‐T 129	100%	Exploration	7,241	‐
Brazil	REC‐T 142	100%	Exploration	6,856	‐
Brazil	REC‐T 224	100%	Exploration	7,192	‐
Brazil	REC‐T 117	100%	Exploration	6,795	‐
Brazil	REC‐T 118	100%	Exploration	7,734	‐

BRAZIL

Tie Field (Reconcavo Basin)

Maha owns and operates, through a wholly‐owned subsidiary, 100% working interests in 6 onshore concession agreements located in the Reconcavo Basin of Brazil, including the oil producing Tie field. The Tie field and the 6 concessions are located in the state of Bahia, onshore Brazil. The 6 concessions are in varying stages of exploration and development. A total of 8 wells had been drilled and 212 km² of 3D seismic had been acquired by the previous Operator over the 41,606 total acres.

Tie‐1 (7‐Tie‐1DP‐BA or "attic" well)

The Tie‐1 well was drilled and completed at the beginning of 2019. Initial production from the Tie‐1 well, which was drilled on a structural high, was 2,913 BOEPD – one of the highest producing wells onshore Brazil. This well was flowing naturally from the Sergi (SG) zone and under jet pump artificial lift from the Aqua Grande (AG) zone. In Q1 of 2021, a workover was carried out to repair a tubing leak and retrieve the downhole jet pump assembly. The well

² As per the current quarter reported net production volumes to Maha before royalties. 1BBL = 6000SCF of gas. Approximately 91% of Maha's oil equivalent production is crude oil.

is now configured as a dual zone jet pump completion and is producing utilising a newly installed quintuplex jet pump.

Tie‐2

At the end of 2020, the Tie‐2 well was drilled and connected to the Tie production facilities and has been producing under natural flow from both zones (comingled).

Tie‐3

The Tie‐3 well was spudded on 18 December 2020 with an objective to intersect the oil‐water contacts of both the AG and SG at the western edge of the field with a view to eventually convert the well to a water injector on the Western flank of the field. This well was completed and tested during the second quarter of 2021.

A remediation workover to remove drilling damage was completed successfully during Q2 2021 and the well has been converted to a jet pump artificial lift well to further increase drawdown and rate

Tie‐4 (Horizontal well)

Maha spudded its first horizontal well, the Tie‐4 well, in July 2021 with a planned Electric Submersible Pump (ESP) artificial lift system. This well will be the first of two horizontal production wells in the Tie field. The well is targeting a 600 m. horizontal section in the AG reservoir and was expected to take ~75 days to drill and complete. Due to the well being drilled as a horizontal production well, the anticipated production volumes are estimated to be larger than the comparable vertical wells in the Tie field. As a result, the well will be completed with a high‐volume ESP for oil production. Both these technologies are 'a first' for Maha on the Tie field and underscores the utilization and benefit of modern technology on a developed production asset. During the current quarter, the Tie‐4 well suffered issues with drillstring twistoffs during the drilling and a sidetrack is currently being initiated. The new completion date of Tie‐4 is anticipated to be around the end of the year. The delay in Tie‐4 has resulted in the deferral of over 171,000 BOE, or 469 BOEPD of production on an annualized basis.

The second horizontal well will be drilled into the Sergi reservoir after Tie‐4, and then followed by a water injection well to the south of the Tie field.

Production Facilities

The Tie Production Facility has been upgraded to handle up to 5 000 BOPD along with associated gas and water production. As the Tie field is not connected to a pipeline system, all oil is exported by trucks. The associated gas is separated and sold locally to two gas customers (GTW and CDGN). Two Ariel natural gas compressors were installed in 2020 to allow for gas reinjection while simultaneously delivering dehydrated gas to GTW and CDGN. Any excess gas produced at Tie can be injected back into the reservoir providing significant operational flexibility and redundancy for Tie field oil production.

Average production from the Tie field during the current quarter was 3,202 BOEPD (2,795 BOPD of oil and 2,443 MSCFPD of gas).

Tartaruga Field (Sergipe‐Alagoas Basin)

Maha has a 75% working interest in the Tartaruga development block, located in the Sergipe Alagoas Basin onshore Brazil. The Tartaruga field is located in the northern half of the Tartaruga Block and produces light (41° API) oil from the Penedo sandstone reservoir. The Penedo sandstone consists of 27 separate stacked sandstone stringers, having all been electrically logged and are believed to contain oil, and of which only 2 of the 27 have been commercially produced (Penedo 1 and Penedo 6).

107D Well (TTG‐2)

This prolific horizontal sidetrack was the first horizontal well in the Penedo sandstone in Brazil. It has paved the way for future horizontal well technology on the Taratruga structure. This well is currently on production on a surface jet pump.

7‐TTG‐1D‐SES Production well (TTG‐1)

During the third quarter the 7‐TTG‐1D‐SES (TTG1) well developed a leak in the completion necessitating a workover to repair the leak. A rig was mobilized during October and the well was worked over and restored to production during the fourth quarter of 2021.

Maha‐1 (7‐TTG‐3D‐SES) Delineation well (TTG‐3)

Maha‐1 was an appraisal well to provide much needed well information for the Tartaruga field Development Plan and targeted to test up to five different intervals in the Penedo sandstone.

Testing of the well is now complete and results are being evaluated to determine the long term plan for the well.

Production Facilities

Current handling facilities at Tartaruga Field allow for approximately 800 BOPD of processing and handling with storage capacity at 1,350 barrels of oil. Current oil production is limited by associated gas flare limitations. Currently, crude oil export is via oil trucks as the facility is not linked to a pipeline system.

Since July 2020, the Company commenced selling associated natural gas to a third‐party company Geracao E Servicos Ltda ("GTW"). The natural gas feeds six generators which produce electricity for field consumption and to the local power grid.

Average production, net to the Company, from the Tartaruga field during the current quarter was 182 BOEPD (171 BOPD of oil and 65 MSCFPD of gas). Production suffered during the quarter due to 7‐TTG‐1D‐SES being shut in for safety reasons as a result of a tubing leak in the downhole completion. This leak was subsequently repaired during October and November.

USA

Illinois Basin

On 31 March, 2020, Maha acquired certain oil producing assets in the Illinois Basin, USA, adding oil and gas leases to Maha's USA footprint. The Illinois Basin is one of the oldest oil producing basins in North America having produced over 4 billion barrels of oil to date. Oil was initially discovered in 1853 according to historical records and oil is found in multiple shallow Dolomite and Sandstone reservoirs. Most producers in the area produce oil from 3 separate reservoirs that act independent of each other. This is a low risk conventional oil play that requires low cost drilling and stimulation operations.

During the quarter, Maha's twelve well drilling and stimulation program was completed and clean up and ramp up of oil production is commencing with wells coming onstream on a regular basis through the fourth quarter. Initial production rates vary between 50 ‐ 75 BOPD for each stimulated well. Current production was curtailed in certain areas where stimulations were being carried out to optimise results.

Average net production from the Illinois basin during the current quarter was 223 BOPD of oil.

LAK Ranch (LAK)

The Company owns and operates a 99% working interest in the LAK Ranch oil field, located on the eastern edge of the multi‐billion‐barrel Powder River Basin in Wyoming, USA.

The LAK Ranch heavy oil asset was shut in at the beginning of 2020 Covid‐19 Pandemic and is currently suspended.

Oman

Block 70

On 5 October 2020, the Company entered into an Exploration and Production Sharing Agreement ("EPSA") with the government of the Sultanate of Oman, for Block 70, an onshore block in Oman. The EPSA was subsequently ratified by Royal Decree of His Majesty the Sultan of Oman on 28 October 2020 and Maha became the operator of the block, holding a 100% working interest. The EPSA covers an initial exploration period of three years with an optional extension period of another three years. In case of a commercial oil or gas discovery, the EPSA can be transformed into a fifteen‐year production license which can be extended for another five years. The EPSA contains provisions on the parties' entitlement to produced oil, natural gas and condensate. Initial consideration for Block 70 was USD 10 million along with USD 0.3 million in certain annual payment obligations.

Block 70 is an onshore block that includes the shallow fully delineated but undeveloped Mafraq oil field. The Mafraq oil field was discovered by Petroleum Development Oman (PDO) in 1988 and was further delineated by four wells and 3D seismic in stages until 2010. Two wells were placed on pump production tests, of which one was placed on a 22‐day test and produced a stable and cumulative volume of over 15,700 barrels of 13 API oil before operations were suspended. The Mafraq oil field is estimated by third parties to contain between 185 – 280 million barrels of original oil in place (OOIP). The productive reservoir is shallow, at approximately 430 meters below ground level.

During 2021, progress has been made towards obtaining necessary approvals and the purchasing of long lead equipment to allow for drilling activities to commence during first half of 2022. The increased rate of new Covid‐19 infections in Oman during the first half of the year, led to tighter Covid‐19 restrictions, including curfews and suspension of entry into the country for non‐Omanis, and is likely have an impact on the Company's initially planned activity timeline.

Financial Results Review

Result

The net result for the current quarter amounted to TUSD 6,083 (Q3 2020: TUSD 1,845) representing earnings per share of USD 0.05 (Q3 2020: USD 0.02). The net result increased compared to the comparative period and was mainly driven by significantly higher revenue which was partly offset by higher operating costs, depreciation, depletion and amortization expense, and finance costs. This was offset by higher other income related to tax credits earned on Brazil value added tax of TUSD 747 and lower general and administrative costs.

The net result for the nine months of 2021 amounted to TUSD 14,224 (Nine Months 2020: TUSD 5,443) representing earnings per share of USD 0.13 (Nine Months 2020: USD 0.05). Higher net result for the nine months period is mainly due to higher revenue for the period as compared to the comparative period even though production volume was mainly in line with the comparative period. Higher production expenses, general and administrative costs, and finance costs were offset slightly by higher other income.

The Company also generated higher quarterly earnings before interest, tax, depletion and amortization (EBITDA) for the third quarter of TUSD 12,909 (Q3 2020: TUSD 5,514) and for the nine months 2021 of TUSD 32,110 (Nine Months 2020: TUSD 15,384) due to the same reasons as above.

Production

			Nine	Nine
			Months	months	Full Year
	Q3 2021	Q3 2020	2021	2020	2020
Delivered Oil (Barrels)3	293,662	302,320	857,566	882,365	1,113,785
Delivered Gas (MSCF)	230,687	162,094	562,775	443,384	566,437
Delivered Oil & Gas (BOE)4	332,110	329,336	951,362	956,262	1,208,191
Daily Volume (BOEPD)	3,610	3,580	3,485	3,490	3,301

Production volumes shown are net working interest volumes before government, gross overriding, and freehold royalties. Approximately 88% (Q3 2020: 92%) of total oil equivalent production was crude oil for Q3 2021.

The average daily production volumes for Q3 2021 increased by 1% as compared to Q3 2020. By the end of the second quarter, production at the Tie field was restored to normal production volumes with all wells onstream and has remained stable at predicted volumes. The Company was anticipating increase in production volumes with the Tie‐4 well coming on production during the third quarter; however, the well has suffered setbacks during drilling the production hole which has resulted in deferral of 469 BOEPD of production on an annualized basis.

Average daily production volumes for the nine months 2021 were in line with the same period in 2020. Lower production volumes for the second quarter lowered the average production volumes for the nine months of 2021.

Revenue

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
Oil and Gas revenue	19,496	11,226	50,488	30,359	39,018
Sales volume (BOE)	329,599	333,301	925,188	932,357	1,174,386
Oil realized price (USD/BBL)	65.76	36.39	59.90	35.34	36.05
Gas realized price (USD/MSCF)	0.86	0.57	0.78	0.66	0.67
Oil Equivalent realized price (USD/BOE)	59.15	33.68	54.57	32.56	33.22
Reference price – Average Brent
(USD/BBL)5	73.47	42.96	67.89	40.92	41.76

Revenue for the current quarter amounted to TUSD 19,496 (Q3 2020: TUSD 11,226), an increase of 74% as compared to Q3 2020. This increase was mainly driven by higher realized oil price by 82%, in line with the higher average Brent oil price for the current quarter, despite lower sales volume by 1% against the comparative quarter. Higher oil realized prices resulted from the improved market conditions for oil and gas commodity prices after significant price declines suffered during 2020 due to the effects of the COVID‐19 pandemic.

Revenue for the nine months 2021 amounted to TUSD 50,488 (Nine Months 2020: TUSD 30,359), an increase of 66% as compared to the nine months 2020 despite lower sales volumes by 1% than the comparative period. The increase in revenue is consistent with the higher oil realized prices whereas prior year oil prices were significantly impacted by the depressed oil and gas market from the COVID‐19 pandemic.

Crude oil realized prices in Brazil are based on Brent price less applicable contractual discounts, reviewed annually, as follows:

³ Full Year 2020 Includes LAK Ranch Oil delivered during the period.

⁴ BOE is Barrels of Oil Equivalent and takes into account gas delivered and sold. 1 bbl = 6,000 SCF of gas

⁵ Reference price is as per U.S. Energy Information Administration website.

Tie Field crude oil

Crude oil from the Tie field is sold to Petrobras and a nearby refinery. For crude oil sold to the refinery, effective 1 April 2021, the discount to Brent oil price is as per the following price‐based scale:

BRENT Price (USD/bbl)	Discount (USD/bbl
< \$30	\$5
Between 30.1 and 40	\$6
Over 40.1	\$8

Crude oil sales to Petrobras from the TIE field are sold at a discount to Brent oil price of \$11.53/bbl for the first 22,680 monthly delivered barrels, and \$7.01 thereafter. Effective 1 April 2021, crude oil sales to Petrobras from the TIE field are sold at a discount to Brent oil price of \$6.48/bbl for the first 22,680 monthly delivered barrels, and \$5.44/bbl thereafter, plus associated taxes calculated as 5% of the net price after applying the contractual discount.

Tartaruga Field crude oil

Crude oil from the Tartaruga field is entirely sold to Petrobras. Up to 1 July, 2021 crude oil from the Tartaruga field was sold at a discount to Brent of USD \$2.91/bbl. (Q2 2020: 0.16/bbl premium). Effective 1 July 2021, crude oil sales to Petrobras from the Tartaruga field are sold at a discount to Brent oil price of \$3.40/bbl.

Illinois Basin

Crude oil from the Illinois Basin is sold to a refinery at the benchmark monthly average WTI price minus a discount of approximately \$3/bbl.

More revenue information is detailed in Note 4 to the Condensed Consolidated Financial Statements.

Royalties

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
Royalties	2,597	1,746	7,091	4,392	5,829
Per unit (USD/BOE)	7.88	5.24	7.66	4.71	4.96
Royalties as a % of revenue	13.3%	15.6%	14.0%	14.5%	14.9%

Royalties are settled in cash and based on realized prices before discounts. Royalty expense increased by 49% and 61% for Q3 2021 and the nine months 2021, respectively, as compared to the same periods in 2020. This increase in royalty expense is consistent with higher revenue for the same periods. Effective royalty rate for Q3 2021 lower than the comparative period of 2020 due to lower sales from the Tartaruga field which has a higher royalty rate as compared to the other fields. Royalty rate for the nine months 2021 is in line with the comparative period in 2020.

ANP Resolution 853/2021 – Reduction of Royalties Rate for Small and Medium‐sized Companies

The National Agency of Petroleum, Natural Gas and Biofuels in Brazil ("ANP") published a resolution allowing for the reduction of the royalty rates on fields operated by small or medium‐sized companies which became effective on 1 November 2021. The royalty reduction shall be applied for by the operator and for each producing field.

In early November, Maha applied for the royalty rate reduction for its producing fields in Brazil and expects an approval within 90 days. The reduced royalty rate will become effective on the production month following the date of signing of the amendment to the concession agreement reflecting this change in the royalty rate.

Maha is considered to be a medium sized company (average annual production less than 10,000 BOEPD in Brazil and abroad) and following a successful application the government royalty rate would be reduced to 7.5% (from 10% currently).

Production expenses

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
Operating costs	2,839	1,996	7,951	5,284	7,536
Transportation costs	492	443	1,299	1,407	2,130
Total Production expenses	3,331	2,439	9,250	6,691	9,666
Per unit (USD/BOE)	10.10	7.32	9.99	7.18	8.23

Production expenses are higher by 37% for the current quarter and amounted to TUSD 3,331 (Q3 2020: 2,439) and higher by 38% for the nine months 2021 and amounted to TUSD 9,250 (Nine Months 2020: 6,691) as compared to the same periods in 2020.

Operating costs are higher during the current quarter and the nine months 2021 as compared to the same periods in 2020 due to several reasons: first, repairs and maintenance costs of certain producing wells were higher than expected and second, the Company's consumption of electricity is much higher than prior periods due to usage of all generators. Finally, current period's operating costs include operating charges for the two gas compressors as these gas compressors' lease commenced during the third quarter of 2020.

Maha's production is trucked to the delivery points therefore transportation costs are directly correlated to the sales volumes. Transportation costs for the current quarter is higher than the comparative period due to increase in the transportation costs as the Company's transportation contract was revised to higher per barrel transportation cost effective May 2021. Tartaruga has higher transportation cost as compared to the Tie field. For the nine months 2021 transportation costs decreased as compared to the same period in 2020 due to lower sales volume in Brazil.

On a per BOE (or unit) basis, production expenses were USD 10.10 per BOE representing an increase by 38% for the current quarter as compared to the comparative period due to the same reasons as above. On a per BOE (or unit) basis, production expenses were USD 9.99 per BOE representing an increase by 39% for the nine months 2021 as compared to the comparative period due to the same reasons as above as well as lower sales volumes for the period.

Operating netback

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
Operating Netback	13,568	7,041	34,147	19,276	23,523
Netback (USD/BOE)	41.17	21.12	36.92	20.67	20.03

Operating netback is calculated as revenue less royalties and production expenses and is a metric used in the oil and gas industry to compare performance internally and with industry peers. Operating netback for the current quarter and the nine months 2021 is 93% and 77%, respectively, higher than the comparative period as a result of higher realized prices during 2021. This was offset by slightly lower sales volume and higher production costs during 2021 periods. Oil and gas prices were significantly lower in the comparative periods due to beginning of the COVID‐19 pandemic.

Depletion, depreciation, and amortization ("DD&A")

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
DD&A	2,104	1,530	5,796	4,018	5,624
DD&A (USD/BOE)	6.38	4.59	6.26	4.31	4.79

The depletion rate is calculated on proved and probable oil and natural gas reserves, taking into account the future development costs to produce the reserves. Depletion expense is computed on a unit‐of‐production basis. The depletion rate will fluctuate on each re‐measurement period based on the capital spending and reserves additions for the period.

DD&A expense for the current quarter amounted to TUSD 2,104 (at an average rate of USD \$6.38 per BOE) which is higher by 38% than the comparative period of Q3 2020 that amounted to TUSD 1,530 (at an average rate of USD \$4.59 per BOE). Even though the sales volumes are slightly lower for the current quarter in comparison to the comparable period, depletion expense and depletion rate on a per BOE basis increased because of the higher depletable base for Brazil which was impacted by the increase in the future development capital costs at yearend 2020. Illinois Basin DD&A expense was relatively similar to the comparable period.

DD&A expense increased by 44% for the nine months 2021 and amounted to TUSD 5,796 (at an average rate of USD \$6.26 per BOE) as compared to TUSD 4,018 (at an average rate of USD \$4.31 per BOE) mainly due to the same reason as above.

General and Administration ("G&A")

			Nine	Nine
			Months	months	Full Year
(TUSD, unless otherwise noted)	Q3 2021	Q3 2020	2021	2020	2020
G&A	1,247	1,414	3,691	3,453	5,939
G&A (USD/BOE)	3.78	4.24	3.99	3.70	5.06

G&A amounts are presented net of certain costs allocated to production expenses. G&A expense for the current quarter amounted to TUSD 1,247 which is 12% lower than the same period in 2020. During Q3 2020, the Company had incurred one‐time G&A expenses related to main market listing fees and associated legal costs.

G&A expense for the nine months 2021 amount to TUSD 3,691 (USD 3.99 per BOE) which is higher by 7% from the comparative period of TUSD 3,453 (USD 3.70 per BOE) mainly due to additional costs incurred for staffing and other administrative costs related to the initiation of work program in Oman during the nine months of 2021.

On a per BOE basis, G&A expenses are lower by 11% and higher by 8%, respectively, than the comparative periods mainly due to the same reasons as described above and lower sales volumes in the current periods.

Exploration and business development costs

Exploration and business development costs amounted to nil for the current quarter and TUSD 6 for the nine months 2021 as compared to TUSD 20 and TUSD 186, respectively, for the comparative periods. Exploration and business development costs are related to costs incurred for the maintenance of the exploration blocks in Brazil and Maha's pre‐exploration study of new areas or new ventures, including business development efforts.

Foreign currency exchange gain or loss

The net foreign currency exchange gain for the current quarter amount to TUSD 58 (Q3 2020: TUSD 57 gain) and for the nine months 2021 amount to TUSD 60 gain (Nine Months 2020: TUSD 86 loss). Foreign exchange movements occur on settlement of transactions denominated in foreign currencies. As of July 1, 2021, Maha Energy AB ("the Parent Company") changed its functional currency from Swedish Krona to US Dollars to better reflect the Company's business activities. This change eliminates the translation of the Parent Company to US Dollars for the presentation purposes. The change in functional currency was accounted for prospectively from 1 July 2021. In accordance with the Swedish Annual Accounts Act (1995:1554), the presentation currency of the Parent Company's financial statements is Swedish Krona.

Other income and loss

Other income for the current quarter amount to TUSD 747 (Q3 2020: nil) and for the nine months 2021 amount to TUSD 1,925 (Nine Months 2020: nil). During the current quarter, the Company recognized other income of TUSD 747 related to tax credits earned on Brazil value added tax known as Imposto sobre Circulação de Mercadorias e Serviços ("ICMS"). ICMS is a tax on the circulation of goods and transportation and communication services, a state sales tax. These tax credits can be applied to importation related duties of the Company or it can be sold to external parties for their utilization.

Net finance costs

Net finance costs for the current quarter amounted to TUSD 2,584 (Q3 2020: TUSD 1,285) and for the nine months 2021 amount to TUSD 7,096 (Nine months 2020: TUSD 3,643) and are detailed in Note 5. Net finance costs are higher for the current periods as compared to the comparative periods mainly due to additional interest expense and amortization of deferred financing fees for the new bank debt (See Note 9). Net finance costs for the nine months 2021 also includes foreign exchange loss of TUSD 784 due to the Parent Company's increased exposure to US dollars fluctuation resulting from the US dollars debt financing in the Parent Company, which had Swedish Krona as the functional currency until 30 June 2021. During the second quarter, Swedish Krona weakened in comparison to US dollar from the time the funds were received by the Company to the end of the quarter resulting in unrealized foreign exchange loss.

Income Taxes

Current tax expense amounted to TUSD 904 for the current quarter and TUSD 2,237 for the nine months 2021 as compared to TUSD 422 and TUSD 985 for the same comparative periods. Current tax expense is higher by 114% for the current quarter as compared to the same period in 2020 mainly due to higher taxable income in Brazil resulting from higher oil and gas prices realized during the quarter. Taxation of corporate profits in Brazil is a combined 34% rate (25% corporate income tax and 9% Social contribution); however, Maha Energy Brazil Ltda. has secured certain tax incentives (SUDENE) in both of its fields until fiscal year 2029 allowing for the reduction of 75% of the corporate income tax from 25% to 6.25%, bringing the combined net tax rate to 15.25%.

Deferred tax expense for the current quarter amounted to TUSD 1,292 and for the nine months 2021 amounted to TUSD 2,817 as compared to deferred tax expense of TUSD 489 and TUSD 1,209 for the same comparative periods. A deferred tax amount arises primarily where there is a difference in depletion charge computation for tax and accounting purposes.

The Company operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Company can vary between 15 and 28 percent. The effective tax rate for the reporting period is affected by several items which do not receive a full tax credit.

Brazil tax reform:

On 1 September 2021, Brazil's House of Deputies approved Bill 2,337 as the comprehensive reform to the Brazilian tax system. If enacted, the bill would reduce the corporate income tax rate, from a combined 34% to 27% (may be reduced further to 26%, subject to certain budgetary targets being met). It would require corporate income taxes to be calculated and paid on a quarterly basis, rather than an annual basis, would establish a 15% withholding tax rate on dividends (currently, zero), eliminate the interest on net equity (i.e., similar to a dividend payment that is deductible in Brazil), require taxpayers to carry out capital reductions at fair market value (currently allowed at book value), and strengthen the rules on disguised distributions of profits, which would require domestic transactions between related parties to be at arm's length (additional compliance requirements).

The legislative process usually takes time in Brazil, and the current wording of the bill may still be amended in the next steps of this process. If the bill is approved, it would be effective 1 January 2022. The result of this decrease in the corporate income tax rate can potentially decrease the Company's deferred tax asset by approximately USD 3.0 million based on 30 September 2021 exchange rate.

Exchange differences on translation of foreign operations

The exchange differences on translation of foreign operations presented in Statement of Comprehensive Earnings amounted to loss of TUSD 8,516 for the current quarter mainly due to US Dollars exchange rate strengthening against Brazilian Reals during the quarter. The functional currency of Company's subsidiary in Brazil is Brazilian Reals; however, for the presentation purpose all assets and liabilities are translated at the period end exchange rate and the Statement of Operations is translated at the average exchange rate of the period. 30 September 2021 USD/BRL exchange rate increased by 9% as compared to 30 June 2021 exchange rate.

The exchange differences on translation of foreign operations presented in Statement of Comprehensive Earnings amounted to loss of TUSD 3,013 for the nine months 2021 mainly due to US Dollars exchange rate strengthening against Brazilian Reals during the period. 30 September 2021 USD/BRL exchange rate increased by 5% as compared to 31 December 2020 exchange rate.

Liquidity and capital resources

The Company manages its capital structure to support the Company's strategic growth. The Company's objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company's financial obligations as they come due. The Company considers its capital structure to include shareholders' equity of USD \$86.8 million (31 December 2020: USD \$55.6 million) plus net debt of USD \$22.8 million (31 December 2020: USD \$29.3 million). At 30 September 2021, the Company's working capital surplus was USD \$13.0 million (31 December 2020: Deficit of USD \$10.0 million), which includes USD \$31.8 million of cash (31 December 2020: USD \$6.7 million).

The Company may adjust its capital structure by issuing new equity or debt and adjusting its capital expenditure program, within its contracted work commitments. To facilitate the management of its capital requirements, the Company prepares annual expenditure budgets that are updated as necessary depending on various factors, including successful capital deployment and general industry conditions. The annual and any subsequent budget updates are approved by the Board of Directors.

On 30 March 2021, the Company entered into a loan agreement (the "Term loan") and equity financing subscription with Brazilian Investment Bank BTG Pactual S.A. for total proceeds of USD 70 million before customary fees and expenses. The proceeds were used to redeem the SEK 300 million bonds payable during the second quarter. The remaining funds are being used to finance capital expenditures across Maha's portfolio and general corporate purposes. The Company's bond holders also exercised the bond warrants during the year, prior to warrants expiration, which provided additional approximately USD 9.0 million cash for the Company. The Company does not have any externally imposed material capital requirements to which it is subject except for the loan covenants (See Note 9).

Share Data

Shares outstanding	A	B	Total
30 September 2021	119,232,330	483,366	119,715,696

During 2021, a total of 10,134,916 bond warrants were exercised at a strike price of SEK 7.45 prior to their expiration on 30 June 2021 and the same number of new class A shares were issued. The remainder of the bond warrants are now expired. The total proceeds from this transaction were SEK 75.5 million (approximately USD 9.0 million) before issuance costs. In addition, 300,000 incentive warrants were converted to class A shares during the year.

As part of the Term loan financing during the second quarter of 2021, Maha received an equity contribution of USD 10 million through a private placement issuance of 7,470,491 new class A shares, at a price of SEK 11.59 per share (See Note 9 for further details).

Risks and Uncertainties

The Company thoroughly examines the various risks to which it is exposed and assesses the impact and likelihood of those risks. The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and to monitor market conditions and the Company's activities. This approach actively addresses risk as an integral and continual part of decision making within the Company and is designed to ensure that all risk is identified, fully acknowledged, understood and communicated well in advance. Nevertheless, oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control. The Board of Directors has overall responsibility for establishment and oversight of the Company's risk management.

A detailed analysis of Maha's operational, financial, and external risks, and the mitigation of those risks through risk management is described in Maha Energy's 2020 Annual Report.

Ongoing COVID‐19 Crisis

Maha has managed to maintain a proactive approach in safeguarding the wellbeing of the Company's employees and contractors and ensuring the virus has minimal impact on its operations. Where possible Maha has temporarily scaled back headcount, implemented work from home policies, implemented practices to monitor and control access to our operation sites via typical COVID monitoring protocols and continue to, at a very minimum, comply with local country legislations. To date Maha has been able to operate all our facilities throughout the pandemic and believe that it will continue to do so going forward. The increased rate of new Covid‐19 infections in Oman over the past months, leading to tighter Covid‐19 restrictions, including curfews and suspension of entry into the country for non‐Omanis, will likely have an impact on the Company's initially planned activity timeline in Oman.

Even after the COVID‐19 outbreaks have subsided, the Company may continue to experience materially adverse impacts to the business as a result of the global economic impact. The Company will continue to monitor this situation and will work to adapting its business to further developments as determined necessary or appropriate.

The current and any future COVID‐19 outbreaks may increase the Company's exposure to, and magnitude of, each of the risks and uncertainties identified in our Annual Report for the year ended December 31, 2020.

Legal matters

The Company has several disclosed legal matters concerning labor, regulatory and operations. All of these are considered routine and consistent with doing business in Brazil. Provisions for lawsuits are estimated in consultation with the Company's Brazilian legal counsel and have been recorded under current and non‐current liabilities and provisions.

Environment, Social, and Governance (ESG)

Through responsible operations and strategic planning, Maha seeks to create long‐term value for all of its stakeholders. Thereby, Maha conducts its operations in a manner respects its workforce, neighboring communities, and the environment. Part of contributing to society and being a good global citizen must entail doing 'what is right', in addition to adhering to laws and regulations.

Environment

As part of the business culture, Maha implements the philosophy of being proactive rather than reactive in its environmental management. By preventing costly and impactful scope changes in development plans, Maha can anticipate and identify potential risks and reduce, if not eliminate, potential environmental and social impacts prior to them possibly happening. Proactive management can also address potential irreversible impacts and allow for decisions to be made on strategy and management, rather than responding out of necessity to a situation. Part of the proactive environmental management strategy is to maximize the use of all resources and reduce waste wherever economically possible. For example, Maha recycle or reinject produced water at the facilities, which not only reduces having to find water from another source, but also reduces waste water treatment requirements. In Brazil, Maha is reducing the release of natural gas by using the waste gas from oil production to generate electricity.

Social

Maha values the relationship with its employees, community members, and other stakeholders. Therefore, efforts are made to engage with its employees and local communities in a transparent and respectful manner. Additionally, Maha seeks to ensure local communities benefit from its operations, both directly and indirectly. Direct hiring and encouraging subcontractors to hire local suppliers wherever possible is a way for Maha to contribute to the local communities and economy. Maha has also connected with Local Community Associations to maintain an open and transparent dialogue with the communities near its operations.

Governance

Maha has a zero‐discrimination tolerance and is committed to promote equal opportunities for employees. Additionally, personal and business ethics are taken seriously at Maha and underlie all the regulations in Corporate Governance. Part of Maha's Corporate Governance is that Maha does not tolerate any form of corrupt practices and has in place Corporate Governance Policies that clearly define how business must be conducted. The best way to prevent corruption is through transparency ‐ one of our core values. The Company has established a Code of Business Conduct and Anti‐Corruption policies for all its employees, contractors, and workers to adhere to. All of Maha's Corporate Governance policies, procedures and guidelines are readily available to employees.

Related Party Transactions

The Company did not enter into any transactions with related parties during the quarter.

Subsequent Events

There are no subsequent events to report.

Parent Company

Business activities for Maha Energy AB focuses on: a) management and stewardship of all Group affiliates, subsidiaries and foreign operations; b) management of publicly listed Swedish entity; c) fundraising as required for acquisitions and Group business growth; and d) business development.

The net result for the Parent Company for Q3 2021 amounted to TSEK ‐59,146 (Q3 2020: TSEK ‐15,869) which is lower than the comparative period mainly due to the impairment of loans and investment in a subsidiary of TSEK 43,828 and higher net finance costs of TSEK 21,467 (Q3 2020: TSEK 6,233) resulting from higher interest expense on the Term loan and higher foreign exchange loss resulting from the exposure to US dollars debt financing. This was offset by lower general and administrative expenses of TSEK 2,210 (Q3 2020: TSEK 4,980), and unrealized foreign currency exchange gain of TSEK 8,359 (Q3 2020: TSEK 4,656 loss).

Financial Statements

Condensed Consolidated Statement of Operations

				Nine months	Nine months
(TUSD) except per share amounts	Note	Q3 2021	Q3 2020	2021	2020
Revenue
Oil and gas sales	4	19,496	11,226	50,488	30,359
Royalties		(2,597)	(1,746)	(7,091)	(4,392)
Net Revenue		16,899	9,480	43,397	25,967
Cost of sales
Production expense		(3,331)	(2,439)	(9,250)	(6,691)
Depletion, depreciation and amortization	6	(2,104)	(1,530)	(5,796)	(4,018)
Gross profit		11,464	5,511	28,351	15,258
General and administration		(1,247)	(1,414)	(3,691)	(3,453)
Stock‐based compensation	12	(159)	(93)	(265)	(253)
Exploration and business development costs		‐	(20)	(6)	(186)
Foreign currency exchange gain (loss)		58	57	60	(86)
Other income		747	‐	1,925	‐
Operating result		10,863	4,041	26,374	11,280
Net finance costs	5	(2,584)	(1,285)	(7,096)	(3,643)
Result before tax		8,279	2,756	19,278	7,637
Current tax expense		(904)	(422)	(2,237)	(985)
Deferred tax expense		(1,292)	(489)	(2,817)	(1,209)
Net result for the period		6,083	1,845	14,224	5,443

Earnings per share basic		0.05	0.02	0.13	0.05
Earnings per share diluted		0.05	0.02	0.13	0.05
Weighted average number of shares:
Before dilution			119,654,826 101,478,706	110,620,223	101,282,417
After dilution			119,876,160 106,578,727	110,915,847	106,658,182

Condensed Consolidated Statement of Comprehensive Earnings

				Nine months	Nine months
(TUSD)	Note	Q3 2021	Q3 2020	2021	2020
Net Result for the period		6,083	1,845	14,224	5,443
Items that may be reclassified to profit or loss:
Exchange differences on translation of
foreign operations		(8,516)	(2,849)	(3,013)	(26,366)
Comprehensive result for the period		(2,433)	(1,004)	11,211	(20,923)

Attributable to:
Shareholders of the Parent Company		(2,433)	(1,004)	11,211	(20,923)

Condensed Consolidated Statement of Financial Position

(TUSD)	Note	30 September 2021	31 December 2020

ASSETS
Non‐current assets
Property, plant and equipment	6	111,927	91,045
Exploration and evaluation assets	7	12,327	11,014
Deferred tax assets		6,465	9,978
Other long‐term assets		427	432
Total non‐current assets		131,146	112,469
Current assets
Prepaid expenses and deposits		1,113	1,434
Crude oil inventory		331	347
Accounts receivable		5,908	3,092
Cash and cash equivalents		31,778	6,681
Total current assets		39,130	11,554
TOTAL ASSETS		170,276	124,023
EQUITY AND LIABILITIES Equity Shareholder's equity	12	86,813	55,556

Liabilities Non‐current liabilities
Bank debt	9	47,079	‐
Decommissioning provision	10	2,878	2,597
Lease liabilities	11	2,655	3,450
Other long‐term liabilities and provisions		4,672	4,825
Total non‐current liabilities		57,284	10,872
Current liabilities
Bonds payable	8	‐	36,022
Bank debt	9	7,500	‐
Accounts payable		8,854	10,731
Accrued liabilities and provisions		8,720	9,599
Current portion of lease liabilities	11	1,105	1,243
Total current liabilities		26,179	57,595
TOTAL LIABILITIES		83,463	68,467
TOTAL EQUITY AND LIABILITIES		170,276	124,023

Condensed Consolidated Statement of Cash Flows

				Nine	Nine
				months	months
(TUSD)	Note	Q3 2021	Q3 2020	2021	2020
Operating Activities
Net result		6,083	1,845	14,224	5,443
Depletion, depreciation, and amortization	6	2,104	1,530	5,796	4,018
Stock based compensation	12	159	93	265	253
Accretion of decommissioning provision	5,10	28	26	91	79
Accretion of bond payable	5	‐	276	497	777
Amortization of deferred financing fees	9	591	‐	833	‐
Interest expense		2,002	1,015	4,955	2,885
Income tax expense		904	422	2,237	985
Deferred tax expense		1,292	489	2,817	1,209
Unrealized foreign exchange amounts		550	(38)	1,063	612
Interest received		11	31	41	96
Interest paid		(1,955)	‐	(5,268)	(1,849)
Tax paid		(584)	(496)	(1,810)	(2,124)
Changes in working capital	16	514	(889)	(1,668)	1,149
Cash from operating activities		11,699	4,304	24,073	13,533

Investing activities
Asset acquisition (net of cash)		‐	‐	‐	(4,152)
Capital expenditures ‐ property, plant, and equipment	6	(12,312)	(2,422)	(33,372)	(11,815)
Capital expenditures ‐ exploration and evaluation assets	7	(640)	(62)	(1,313)	(247)
Restricted cash release		‐	161	‐	131
Cash used in investment activities		(12,952)	(2,323)	(34,685)	(16,083)
Financing activities
Lease payments	11	(330)	(50)	(952)	(165)
Repayment of bonds payable	8	‐	‐	(35,919)	‐
Bank debt borrowing	9	‐	‐	60,000	‐
Paid financing fees	9	910	‐	(5,102)	‐
Shares subscription (net of issue costs)	12	(943)	‐	9,047	‐
Exercise of warrants (net of issue costs)	12	(27)	204	9,191	836
Cash from (used in) financing activities		(390)	154	36,265	671

Change in cash and cash equivalents		(1,643)	2,135	25,653	(1,879)
Cash and cash equivalents at the beginning
of the period		34,139	15,699	6,681	22,450
Currency exchange differences in cash and
cash equivalents		(718)	200	(556)	(2,537)
Cash and cash equivalents at the
end of the period		31,778	18,034	31,778	18,034

Condensed Consolidated Statement of Changes in Equity

				Retained	Total
		Contributed	Other	(Deficit)	Shareholders'
(TUSD)	Share Capital	Surplus	Reserves	Earnings	Equity
Balance at 1 January 2020	122	64,840	(10,772)	33,669	87,859

Comprehensive result
Result for the period	‐	‐	‐	5,443	5,443
Currency translation difference	‐	‐	(26,366)	‐	(26,366)
Total comprehensive result	‐	‐	(26,366)	5,443	(20,923)
Transactions with owners
Stock based compensation	‐	253	‐	‐	253
Exercise of warrants (net of issue costs)	‐	835	‐	‐	835
Total transactions with owners	‐	1,088	‐	‐	1,088
Balance at 30 September 2020	122	65,928	(37,138)	39,112	68,024

Comprehensive result
Result for the period	‐	‐	‐	(15,702)	(15,702)
Currency translation difference	‐	‐	3,042	‐	3,042
Total comprehensive result	‐	‐	3,042	(15,702)	(12,660)
Transactions with owners
Stock based compensation	‐	85	‐	‐	85
Exercise of warrants (net of issue costs)	‐	107	‐	‐	107
Total transactions with owners	122	192	‐	‐	314
Balance at 31 December 2020	122	66,120	(34,096)	23,410	55,556
Comprehensive result
Result for the period	‐	‐	‐	14,224	14,224
Currency translation difference	‐	‐	(3,013)	‐	(3,013)
Total comprehensive result	‐	‐	(3,013)	14,224	11,211
Transactions with owners
Stock based compensation	‐	265	‐	‐	265
Share issuance (net of issue costs)	10	10,493	‐	‐	10,503
Exercise of warrants (net of issue costs)	14	9,264	‐	‐	9,278
Total transactions with owners	24	20,022	‐	‐	20,046
Balance at 30 September 2021	146	86,142	(37,109)	37,634	86,813

Parent Company Statement of Operations

			Nine	Nine
			months	months
(Expressed in thousands of Swedish Krona)	Q3 2021	Q3 2020	2021	2020
Revenue	‐	‐	‐	‐
Expenses
General and administrative	(2,210)	(4,980)	(7,213)	(10,596)
Foreign currency exchange gain(loss)	8,359	(4,656)	5,635	(12,703)
Operating result	6,149	(9,636)	(1,578)	(23,299)

Impairment of loans and investments	(43,828)	‐	(43,828)	‐
Net finance costs	(21,467)	(6,233)	(35,370)	(18,091)
Result before tax	(59,146)	(15,869)	(80,776)	(41,390)
Income tax Net and comprehensive result for the period	‐ (59,146)	‐ (15,869)	‐ (80,776)	‐ (41,390)

Parent Company Balance Sheet
(Expressed in thousands of Swedish Krona)	Note	30 September 2021		31 December 2020
Assets
Non‐current assets
Investment in subsidiaries		6,646		4,368
Loans to subsidiaries		632,695		471,839
		639,341		476,207
Current assets
Accounts receivable and other		309		116
Restricted cash		50		50
Cash and cash equivalents		155,057		7,292
		115,416		7,458
Total Assets		754,757		483,665

Equity and Liabilities
Restricted equity
Share capital		1,316		1,117
Unrestricted equity
Contributed surplus		685,071		516,500
Retained earnings		(418,210)		(337,434)
Total unrestricted equity		266,861		179,066

Total equity		268,177		180,183
Non‐current liabilities
Bank debt	9	418,835		‐

Current liabilities
Accounts payable and accrued liabilities		2,050		7,658
Bank debt	9	65,695		‐
Bonds Payable	8	‐		295,824
		67,745		303,482

Total liabilities		486,580		303,482
Total Equity and Liabilities		754,757		483,665

Parent Company Statement of Changes in Equity

	Restricted equity	Unrestricted equity
		Contributed	Retained
(Thousands of Swedish Krona)	Share capital	surplus	Earnings	Total Equity
Balance at 1 January 2020	1,113	504,682	(79,092)	426,703
Total comprehensive income	‐	‐	(41,390)	(41,390)
Transaction with owners
Stock based compensation	‐	2,366	‐	2,366
Exercise of bond warrants
(net of issuance costs)	9	6,112	‐	6,121
Exercise of incentive warrants	3	1,747		1,750
C2 shares cancellation	(9)	‐	‐	(9)
Total transaction with owners	3	10,225	‐	10,228
30 September 2020	1,116	514,907	(120,482)	395,541

Total comprehensive income	‐	‐	(216,952)	(216,952)
Transaction with owners
Stock based compensation	‐	777	‐	777
Exercise of bond warrants
(net of issuance costs)	1	816	‐	817
Total transaction with owners	1	1,593	‐	1,594
Balance at 31 December 2020	1,117	516,500	(337,434)	180,183
Total comprehensive income	‐	‐	(80,776)	(80,776)
Transaction with owners
Stock based compensation	‐	2,270	‐	2,270
Share issuance (net of issuance costs)	82	88,178	‐	88,260
Exercise of warrants (net of issuance
costs)	117	78,123	‐	78,240
Total transaction with owners	199	168,571	‐	168,770
Balance at 30 September 2021	1,316	685,071	(418,210)	268,177

Notes to the Condensed Consolidated Financial Statements

1. Corporate information

Maha Energy AB ("Maha (Sweden)" or "the Company") Organization Number 559018‐9543 and its subsidiaries (together "Maha" or "the Group") are engaged in the acquisition, exploration and development of oil and gas properties.

The Company has operations in Brazil, Oman and the United States. The head office is located at Strandvägen 5A, SE‐114 51 Stockholm, Sweden. The Company's subsidiary, Maha Energy Inc., maintains its technical office at Suite 240, 23 Sunpark Drive SE, Calgary, Canada. The Company has an office in Rio de Janeiro, Brazil and operations offices in Grayville, IL and Newcastle, WY, USA.

2. Basis of presentation

The unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"), and the Swedish Annual Accounts Act.

The unaudited interim condensed consolidated financial statements are stated in thousands of United States Dollars (TUSD), unless otherwise noted, which is the Company's presentation and functional currency. These unaudited interim consolidated financial statements have been prepared on a historical cost basis, except for certain financial instruments which are stated at fair value.

The accounting principles as described in the Annual Report 2020 have been used in the preparation of this report. Certain information and disclosures normally included in the notes to the annual consolidated financial statements have been condensed or have been disclosed on an annual basis only. Accordingly, these unaudited interim condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements for the year ended 31 December 2020.

The financial reporting of the Parent Company (Maha Energy AB) has been prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 Reporting for legal entities, issued by the Swedish Financial Reporting Board and the Annual Accounts Act.

Under Swedish company regulations it is not allowed to report the Parent Company results in any other currency than Swedish Krona or Euro and consequently the Parent Company's financial information is reported in Swedish Krona and not the Group's presentation currency of US Dollar.

Changes in Accounting Policies

During the third quarter 2021, the Company did not adopt any new standards and interpretations or amendments thereto applicable for financial periods beginning on or after 1 January 2021.

Going Concern

The Company prepared these consolidated financial statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. The Company manages its capital structure to support the Company's strategic growth and has positive cash flow from operations.

3. Segment Information

Operating segments are based on a geographic perspective and reported in a manner consistent with the internal reporting provided to the executive management as follows:

‐ Brazil: Includes all oil and gas activities of exploration and production in Tie Field and Tartaruga Field.

‐ United States of America (USA): Includes all oil and gas activities in the Illinois Basin and LAK Field.
‐ Corporate: The Corporate segment aggregates costs incurred at the Company's corporate office in Sweden and the technical and support office in Canada as well as initial costs related to activities in Oman. These operating segments have similar economic characteristics as they do not currently generate revenue.

"Adjustments" segment primarily includes consolidation adjustments and eliminations between segments.

The following tables present the operating result for each segment. Revenue and income relate to external (non‐ intra group) transactions.

(TUSD)	Brazil	USA	Corporate	Adjustments	Consolidated
Nine months 2021
Revenue	46,734	3,754	‐	‐	50,488
Royalties	(6,165)	(926)	‐	‐	(7,091)
Production and operating	(8,208)	(1,042)	‐	‐	(9,250)
Depletion, depreciation, and
amortization	(4,850)	(899)	(47)	‐	(5,796)
General and administration	(576)	(83)	(3,032)	‐	(3,691)
Stock‐based compensation	‐	‐	(265)	‐	(265)
Exploration and business
development cost	‐	‐	(6)	‐	(6)
Foreign currency exchange (loss)gain	22	76	1,028	(1,066)	60
Other income	1,925	‐	‐	‐	1,925
Operating results	28,882	880	(2,322)	(1,066)	26,374
Net finance costs	(1,838)	(14)	(5,244)	‐	(7,096)
Current tax	(2,237)	‐	‐	‐	(2,237)
Deferred tax	(2,817)	‐	‐	‐	(2,817)

Net results	21,990	866	(7,566)	(1,066)	14,224

(TUSD)	Brazil	USA	Corporate	Adjustments	Consolidated
Nine months 2020
Revenue	29,484	875	‐	‐	30,359
Royalties	(4,184)	(208)	‐	‐	(4,392)
Production and operating	(6,159)	(532)	‐	‐	(6,691)
Depletion, depreciation and
amortization	(3,656)	(341)	(21)	‐	(4,018)
General and administration	(68)	(211)	(3,174)	‐	(3,453)
Stock‐based compensation	‐	‐	(253)	‐	(253)
Exploration and business
development cost	‐	(40)	(146)	‐	(186)
Foreign currency exchange (loss)gain	533	(5)	(472)	(142)	(86)
Operating results	15,950	(462)	(4,066)	(142)	11,280
Net finance costs	(1,706)	(14)	(1,923)	‐	(3,643)
Current tax	(985)	‐	‐	‐	(985)

Net results 12,050 (476) (5,989) (142) 5,443

4. Revenue

The Company derives revenue from the transfer of goods at a point in time in the following major commodities from oil and gas production in the geographic regions of Brazil and the USA:

			Nine months	Nine months
TUSD	Q3 2021	Q3 2020	2021	2020
Brazil
Crude oil	17,728	10,615	46,317	29,158
Natural gas	187	93	417	326
Brazil oil and gas sales	17,915	10,708	46,734	29,484
United States oil sales	1,581	518	3,754	875
Total revenue from contracts with
customers	19,496	11,226	50,488	30,359

Revenue is measured at the consideration specified in the contracts and represents amounts receivable net of discounts and sales taxes. Performance obligations associated with the sale of crude oil are satisfied when control of the product is transferred to the customer. This occurs when the oil is physically transferred at the delivery point agreed with the customer and the customer obtains legal title.

The Company had one main customer during Q3 2021 (Q3 2020: two) and during nine months 2021 (Nine Months 2020: two) that individually accounted for more than 10 percent of the Company's consolidated gross sales. Total sales to this customer for Q3 2021 were approximately USD \$14.1 million (Q3 2020: \$10.6 million) and for nine months 2021 were approximately USD 38.4 million (Nine months 2020: \$29.1 million), which are included in the Company's Brazil operating segment. There were no intercompany sales or purchases of oil and gas during the period.

The Company had no contract asset or liability balances during the period presented. As at 30 September 2021, accounts receivable included \$1.9 million of sales revenue which related to the current quarter production.

5. Finance Costs

			Nine	Nine
			months	months
TUSD	Q3 2021	Q3 2020	2021	2020
Interest on bond payable (Note 8)	‐	1,010	1,463	2,870
Accretion of bond payable (Note 8)	‐	276	497	777
Accretion of decommissioning provision (Note 10)	28	26	91	79
Amortisation of deferred financing fees (Note 9)	590	‐	833	‐
Foreign currency exchange loss (gain)	‐	‐	784	‐
Interest expense (Note 9)	2,002	5	3,491	15
Interest income	(36)	(32)	(63)	(98)
	2,584	1,285	7,096	3,643

6. Property, Plant and Equipment (PP&E)

(TUSD)	Oil and gas properties	Equipment and Other	Right‐of‐use assets	Total
Cost
31 December 2019	83,917	2,163	813	86,893
Additions	26,967	114	5,510	32,591
Acquisition	4,538	‐	‐	4,538
Change in decommissioning cost	614	‐	‐	614

Currency translation adjustment	(19,290)	(120)	(305)	(19,715)
31 December 2020	96,746	2,157	6,018	104,921
Additions	30,319	76	‐	30,395
Disposition	‐	‐	(30)	(30)
Change in decommissioning cost	251	‐	‐	251
Currency translation adjustment	(4,412)	(245)	5	(4,652)
30 September 2021	122,904	1,988	5,993	130,885

Accumulated depletion, depreciation and amortization
31 December 2019	(9,751)	(697)	(202)	(10,650)
DD&A	(5,033)	(68)	(475)	(5,576)
Currency translation adjustment	2,271	14	65	2,350
31 December 2020	(12,513)	(751)	(612)	(13,876)
DD&A	(4,648)	(103)	(959)	(5,710)
Currency translation adjustment	602	14	12	628
30 September 2021	(16,559)	(840)	(1,559)	(18,958)

Carrying amount
31 December 2020	84,233	1,406	5,406	91,045
30 September 2021	106,345	1,148	4,434	111,927

7. Exploration and Evaluation Assets (E&E)

	TUSD
31 December 2019	21,216
Additions in the period	400
Oman acquisition	10,350
Impairment	(21,000)
Change in estimates	48
31 December 2020	11,014
Additions in the period	1,313
30 September 2021	12,327

8. Bonds payable

	TUSD	TSEK
31 December 2019	30,621	286,037
Accretion of bond liability	1,063	9,787
Effect of currency translation	4,338	‐
31 December 2020	36,022	295,824
Accretion of bond liability	497	4,176
Repayment of bonds	(35,919)	(300,000)
Effect of currency translation	(600)	‐
30 September 2021	‐	‐

The bonds were set to mature on 29 May 2021; however, on May 5, 2021, the Company redeemed the outstanding Bonds. The Bonds redeemed at an amount equal to 100.00 per cent of the nominal amount (i.e. SEK 100,000 per Bond) plus, as at May 5, 2021, accrued interest of TSEK 15,600 was disbursed to the Bondholders. No early redemption premiums were paid as the Bonds were redeemed at 100 percent of their nominal amount.

9. Bank debt

	TUSD	TSEK
Bank debt	60,000	525,552
Deferred financing costs	(5,421)	(41,022)
30 September 2021	54,579	484,530

Less: Current portion	7,500	65,695
Noncurrent	47,079	418,835

On 30 March 2021, the Company entered into a credit agreement for a senior secured term loan of USD 60 million (the "Term Loan"), maturing 31 March 2025. The proceeds were used to redeem the outstanding SEK 300 million bond and to fund the Company's oil and gas production expansion program.

The Term Loan bears interest at a step‐rate increasing from 12.75% to 13.5% as nearing maturity time, payable quarterly in arrears and secured by substantially all the assets and shares of Maha Energy and its subsidiaries. The principal amount is to be repaid in quarterly instalments over the four (4) year period, commencing 15 months from the credit agreement date. From the date of the credit agreement and up to disbursement on 23 April 2021 a commitment fee equal to an annual rate of 12.60% was payable. Following disbursement, the Company redeemed the Senior Secured Bond on 5 May 2021 for a total amount of SEK 315.6 million, including accrued interest (see Note 8).

The Term Loan requires the Company to maintain certain covenants including a Net interest‐bearing debt to trailing twelve months EBITDA ratio of not greater than 3.0 at the end of each quarter. Under the terms of the loan, the Company is subject to certain restrictions in its ability to make certain payments and distributions to persons outside of the Maha Group, as well as other customary provisions applicable for similar credit agreements.

As part of the closing of the financing transaction, Maha also received an equity contribution of USD 10 million through the Private Placement issuance of 7,470,491 new shares, at a price of SEK 11.59 per share, representing a 10% discount to the last 15 days volume weighted average share price prior to the closing. This discount amounted to USD \$1.1 million and was proportionately allocated to deferred financing cost and equity issuance cost.

The Company recorded directly attributable transaction costs of USD 5.7 million as deferred financing costs which also includes part of the 10% discount on the Private Placement of Maha shares. Deferred financing costs will be amortized over the life of the Term loan.

10. Decommissioning Provision

The following table presents the reconciliation of the opening and closing decommissioning provision:

	(TUSD)
31 December 2019	2,175
Accretion expense	108
Additions	168
Dome Acquisition (Note 6)	68
Change in estimate	378
Foreign exchange movement	(300)
31 December 2020	2,597
Accretion expense	91
Additions	251
Foreign exchange movement	(61)
30 September 2021	2,878

11. Lease Liability

(TUSD)
31 December 2019	611
Additions	4,974
Interest expense	21
Lease payments	(450)
Foreign currency translation	(463)
31 December 2020	4,693
Additions	‐
Interest expense	91
Lease payments	(952)
Foreign currency translation	(72)
30 September 2021	3,760

Less current portion	1,105
Lease liability – non current	2,655

12. Share Capital

Shares outstanding	A	B	Total
31 December 2019	92,456,550	7,960,318	100,416,868
Exercise of bond warrants	949,853	‐	949,853
Conversion of convertible B shares	7,476,952	(7,476,952)	‐
Exercise of incentive warrants	263,330	‐	263,330
31 December 2020	101,146,685	483,366	101,630,051
Exercise of bond warrants	10,134,916	‐	10,134,916
Exercise of incentive warrants	480,238	‐	480,238
Share subscription	7,470,491	‐	7,470,791
30 September 2021	119,232,330	483,366	119,715,696

As at 30 September 2021 Maha A TO2 share purchase warrants outstanding were as follows:

	Number of Warrants	Exercise Price	Exercise Price
	#	SEK	USD
31 December 2019	11,352,182	7.45	0.80
Exercised – Q1	(827,500)	7.45	0.78
Exercised – Q2	(6,446)	7.45	0.74
Exercised – Q3	(5,684)	7.45	0.82
Exercised – Q4	(110,223)	7.45	0.86
31 December 2020	10,402,329	7.45	0.91
Exercised – Q1	(136,963)	7.45	0.90
Exercised – Q2 6	(9,997,953)	7.45	0.88
Expired	(267,413)	7.45	0.88
30 September 2021	‐	‐	‐

⁶ Q2 exercised warrants include 2,881,345 warrants exercised during Q1 for which shares were issued in Q2.

Warrant Incentive Program

The Company has an incentive program as part of the remuneration package for management and employees.

Warrants			Number of warrants
incentive		Exercise
programme		price,		Issued	Expired	Exercised	Cancelled	30 September
	Exercise period	SEK	1 Jan 2021	2021	2021	2021	2021	2021
2018
incentive	1 May 2021 – 30
programme 2019	November 2021	9.20	750,000	‐	‐	300,000	‐	450,000
incentive	1 September 2022
programme 2020	– 28 February 2023	28.10	500,000	‐	‐	‐	‐	500,000
incentive	1 September 2023
programme 2021	– 29 February 2024	10.90	460,000	‐	‐	‐	‐	460,000
incentive	1 June 2021 – 28
programme 2021	February 2025	12.40	‐	1,048,286	‐	‐	‐	1,048,286
incentive	1 June 2023 – 29
programme	February 2024	12.40	‐	524,143	‐	‐	‐	524,143
Total			1,710,000	1,572,429	‐	(300,000)	‐	2,982,429

Each warrant shall entitle the warrant holder to subscribe for one new Share in the Company at the subscription price per share. The fair value of the warrants granted under the warrant incentive program has been estimated on the grant date using the Black & Scholes model.

Weighted average assumptions and fair value are as follows:

	2021
	Incentive Programme
Risk free interest rate (%)	‐0.03
Average Expected term (years)	3.25
Expected volatility (%)	55
Forfeiture rate (%)	10.0
Weighted average fair value (SEK)	4.32

Total share‐based compensation expense for Q3 2021 was TUSD 159 (Q3 2020: TUSD 93).

13. Financial assets and liabilities

For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:

– Level 1: based on quoted prices in active markets;

– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;

– Level 3: based on inputs which are not based on observable market data.

The Company's cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities are assessed on fair value hierarchy described above. The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying value due to the short term to maturity of these instruments. The bank debt is carried at amortized cost and which approximates the fair value.

14. Management of financial risk

A detailed analysis of Maha's operational, financial, and external risks and mitigation of those risks through risk management is described in Maha Energy's 2020 Annual Report. The current and any future COVID‐19 outbreaks may increase the Company's exposure to, and magnitude of, each of the risks and uncertainties identified in our Annual Report for the year ended December 31, 2020. The extent to which the COVID‐19 impacts Maha's business, results of operations and financial conditions will depend on future developments, which are highly uncertain and are difficult to predict. Even after the COVID‐19 outbreaks have subsided, the Company may continue to experience materially adverse impacts to the business as a result of the global economic impact. The Company will continue to monitor this situation and will work to adapting its business to further developments as determined necessary or appropriate.

15. Management of Capital

The Company manages its capital structure to support the Company's strategic growth. The Company's objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company's financial obligations as they come due. The Company considers its capital structure to include shareholders' equity of USD \$86.8 million (31 December 2020: USD \$55.6 million) plus net debt of USD \$22.8 million (31 December 2020: 29.3 million). At 30 September 2021, the Company's working capital surplus was USD \$13.0 million (31 December 2020: Deficit of USD \$10.0 million), which includes USD \$31.8 million of cash (31 December 2020: USD \$6.7 million).

On 30 March 2021, the Company entered into a credit agreement for a senior secured Term loan of USD 60 million maturing 31 March 2025. In addition, the Company issued shares for additional USD 10 million equity financing. Proceeds from the debt financing was used to redeem the outstanding bonds payable of SEK 300 million. The remaining funds are being used to finance capital expenditures across Maha's portfolio and general corporate purposes. The Company's bond holders also exercised the bond warrants during the year, prior to warrants expiration, which provided additional approximately USD 9.0 million cash for the Company. The Company does not have any externally imposed material capital requirements to which it is subject except for the loan covenants (See Note 9).

The Company may adjust its capital structure by issuing new equity or debt and adjusting its capital expenditure program, as allowed pursuant to contracted work commitments. To facilitate the management of its capital requirements, the Company prepares annual expenditure budgets that are updated as necessary depending on various factors, including successful capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors.

16. Changes in non‐cash Working Capital

(TUSD)	30 September 2021	30 September 2020
Change in:
Accounts receivable	(2,843)	844
Inventory	53	98
Prepaid expenses and deposits	320	109
Accounts payable and accrued liabilities	802	98
Total	(1,668)	1,149

17. Pledged Assets

As at 30 September 2021, the Company has pledged assets in relation to the security of the Term Loan whereby the Parent Company has pledged shares of all its subsidiaries and concessions rights and other assets in Brazil with a book value of USD 50.8 million, including adjustments for the consolidation purposes.

The Company redeemed the Senior Secured Bond on 5 May 2021 for which the Company has pledged the assets and as a result, these pledges were subsequently released.

The Company also has financial guarantees in relation to its work commitments in Brazil and has contractual commitments in the USA and Oman (See Note 18).

18. Commitments and Contingencies

The Company has 7 concession agreements with the National Agency of Petroleum, Natural Gas and Biofuels in Brazil ("ANP"). Certain of these blocks are subject to work and abandonment commitments in relation to these exploration blocks which are guaranteed with certain credit instruments. These commitments are in the normal course of the Company's exploration business and the Company plans to fund any related work or penalty, if necessary, with existing cash balances, cash flow from operations and available financing sources.

During the current quarter, the Company was granted extensions until November 2024 under certain non‐ conventional drilling programs. The Company has also applied for the waiver from the penalties under the unconventional vocation of these blocks and court's decision to suspend unconventional exploratory activities in the Recôncavo Basin.

In the Illinois Basin, the Company has commitments to drill and complete four gross wells (3 net wells) during 2021. In addition, a future contingent consideration of USD 3.0 million is possible if certain oil prices and production level milestones are met before 2023. Maha and its subsidiaries are under no obligation to reach the production level set out for the production milestone. The company had not recorded this contingent consideration.

With the acquisition of the Block 70 in Oman, the Company will undertake minimum work obligations during the initial exploration period of three years which include interpretation and reprocessing of 3D seismic and drilling 10 (ten) shallow wells. Costs for these activities are estimated at USD 20 MUSD.

Key Financial Data

Maha believes that the alternative performance measures provide useful supplemental information to management, investors, securities analysts, and other stakeholders and are meant to provide an enhanced insight into the financial development of Maha's business operational.

Financial data
TUSD			Nine months	Nine months
	Q3 2021	Q3 2020	2021	2020
Revenue	19,496	11,226	50,488	30,359
Operating netback	13,568	7,041	34,147	19,276
EBITDA	12,909	5,514	32,110	15,384
Net result	6,083	1,845	14,224	5,443
Cash flow from operations	11,699	4,304	24,073	13,533
Free cash Flow	(1,253)	1,981	(10,612)	(2,550)
Net debt (TUSD)	22,801	14,696	22,801	14,696

Key ratios

			Nine months	Nine months
	Q3 2021	Q3 2020	2021	2020
Return on equity (%)	7	3	16	8
Equity ratio (%)	51	55	51	55
NIBD/EBITDA	0.65	0.62	0.65	0.62
TIBD/EBITDA	1.57	1.38	1.57	1. 38

Data per share

			Nine months	Nine months
	Q3 2021	Q3 2020	2021	2020
Weighted number of shares
(before dilution)	119,654,826	101,478,706	110,620,223	101,282,417
Weighted number of shares
(after dilution)	119,876,160	106,578,727	110,915,847	106,658,182
Earnings per share before
dilution, USD	0.05	0.02	0.13	0.05
Earnings per share after dilution,
USD	0.05	0.02	0.13	0.05
Dividends paid per share	n/a	n/a	n/a	n/a

Relevant reconciliation of Alternative Performance Measures:

Operating Netback

			Nine months	Nine months
(TUSD)	Q3 2021	Q3 2020	2021	2020
Revenue	19,496	11,226	50,488	30,359
Royalties	(2,597)	(1,746)	(7,091)	(4,392)
Operating Expenses	(3,331)	(2,439)	(9,250)	(6,691)
Operating netback	13,568	7,041	34,147	19,276

EBITDA

			Nine months	Nine months
(TUSD)	Q3 2021	Q3 2020	2021	2020
Operating results	10,863	4,041	26,374	11,280
Depletion, depreciation and amortization	2,104	1,530	5,796	4,018
Foreign currency exchange loss / (gain)	(58)	(57)	(60)	86
EBITDA	12,909	5,514	32,110	15,384

Free cash flow

			Nine months	Nine months
(TUSD)	Q3 2021	Q3 2020	2021	2020
Cash flow from operating activities	11,699	4,304	24,073	13,533
Less: cash used in investing activities	(12,952)	(2,323)	(34,685)	(16,083)
Free cash flow	(1,253)	1,981	(10,612)	(2,550)

Net debt
			Nine months	Nine months
(TUSD)	Q3 2021	Q3 2020	2021	2020
Bank debt	54,579	‐	54,579	‐
Bonds payable	‐	32,730	‐	32,730
Less: cash and cash equivalents	(31,778)	(18,034)	(31,778)	(18,034)
Net debt	22,801	14,696	22,801	14,696

Key Ratio Definition

Cash flow from operations: Cash flow from operating activities in accordance with the consolidated statement of cash flow.

EBITDA (Earnings before interest, taxes, depreciation, and amortization and impairment): Operating profit before depletion of oil and gas properties, depreciation of tangible assets, impairment, foreign currency exchange adjustments, interest and taxes.

Earnings per share: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year.

Earnings per share fully diluted: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares after considering any dilution effect for the year.

Equity ratio: Total equity divided by the balance sheet total assets.

Free cash flow: Cash flow from operating activities less cash flow from investing activities in accordance with the consolidated statement of cash flow.

Net debt: Interest bearing debt, excluding leases, less cash and cash equivalents.

Net debt to EBITDA ratio (NIBD/EBITDA): Net interest bearing debt divided by trailing 4 quarters EBITDA.

Operating netback: Operating netback is defined as revenue less royalties and operating expenses.

Return on equity: Net result divided by ending equity balance

Total debt to EBITDA ratio (TIBD/EBITDA): Total interest bearing debt divided by trailing 4 quarters EBITDA.

Weighted average number of shares for the year: The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue.

Weighted average number of shares for the year fully diluted: The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue after considering any dilution effect.

Board Assurance

The Managing Director and the Chairman of the Board certify that the interim report for the nine months ended 30 September 2021 gives a fair view of the performance of the business, position, and income statements of Maha Energy AB (publ.) and Maha Energy Group and describes the principal risks and uncertainties to which the Company and the Group are exposed.

Approved by the Board

Stockholm, 22 November 2021

_Jonas Lindvall____________________ Jonas Lindvall, Director

_Harald Pousette____________________ Harald Pousette, Chairman

Review Report

This is a translation of the Swedish language original. In the events of any differences between this translation and the Swedish original the latter shall prevail.

Independent Auditor's Report on the review of the interim report for the period of 1 January‐30 September 2021.

To the board of Directors of Maha Energy AB (publ) Corp. Reg.No. 559018‐9543.

Introduction

We have reviewed the interim report for Company AB (publ) for the period January 1 ‐ September 30, 2021. The Board of Directors and the Managing Director are responsible for the preparation and presentation of this interim report in accordance with IAS 34 and the Annual Accounts Act. Our responsibility is to express a conclusion on this interim report based on our review.

Scope of Review

We conducted our review in accordance with the International Standard on Review Engagements ISRE 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review has a different focus and is substantially less in scope than an audit conducted in accordance with ISA and other generally accepted auditing practices. The procedures performed in a review do not enable us to obtain a level of assurance that would make us aware of all significant matters that might be identified in an audit. Therefore, the conclusion expressed based on a review does not give the same level of assurance as a conclusion expressed based on an audit.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the interim report is not, in all material respects, prepared for the Group in accordance with IAS 34 and the Annual Accounts Act, and for the Parent Company in accordance with the Annual Accounts Act.

Gothenburg, 22 November 2021

Deloitte AB

Fredrik Jonsson Authorized Public Accountant

Financial calendar

2021 Fourth Quarter: 28 February 2022 2022 First Quarter: 19 May 2022 2022 Second Quarter: 15 August 2022 2022 Third Quarter: 14 November 2022

Contact information

For further information please contact:

Jonas Lindvall (CEO) Tel: +46 8 611 05 11 Email: [email protected]

Andres Modarelli (CFO) Tel: +46 8 611 05 11 Email: [email protected]

Victoria Berg (Investor Relations) Tel: +46 8 611 05 11 Email: [email protected]

Maha Energy AB Head Office Strandvägen 5A SE‐114 51 Stockholm, Sweden +46 8 611 05 11 Technical Office Suite 240, 23 Sunpark Drive SE Calgary, Alberta T2X 3V1 +1‐403‐454‐7560

Email: [email protected]

AI Terminal

Maha Energy

3170_10-q_2021-11-22_872c197e-e4f4-4cd1-a3df-dab9c7084370.pdf

Highlights

Third Quarter 2021

Nine months Ended 30 September 2021

Financial Summary

Definitions

Abbreviations Oil related terms and measurements

Letter to shareholders

Financial Report for the Third Quarter ended 30 September 2021

OPERATIONAL AND FINANCIAL REVIEW

Strategy

Assets

BRAZIL

Tie Field (Reconcavo Basin)

Tie‐1 (7‐Tie‐1DP‐BA or "attic" well)

Tie‐2

Tie‐3

Tie‐4 (Horizontal well)

Production Facilities

Tartaruga Field (Sergipe‐Alagoas Basin)

107D Well (TTG‐2)

7‐TTG‐1D‐SES Production well (TTG‐1)

Maha‐1 (7‐TTG‐3D‐SES) Delineation well (TTG‐3)

Production Facilities

USA

Illinois Basin

LAK Ranch (LAK)

Oman

Block 70

Financial Results Review

Result

Production

Revenue

Tie Field crude oil

Tartaruga Field crude oil

Illinois Basin

Royalties

ANP Resolution 853/2021 – Reduction of Royalties Rate for Small and Medium‐sized Companies

Production expenses

Operating netback

Depletion, depreciation, and amortization ("DD&A")

General and Administration ("G&A")

Exploration and business development costs

Foreign currency exchange gain or loss

Other income and loss

Net finance costs

Income Taxes

Brazil tax reform:

Exchange differences on translation of foreign operations

Liquidity and capital resources

Share Data

Risks and Uncertainties

Ongoing COVID‐19 Crisis

Legal matters

Environment, Social, and Governance (ESG)

Environment

Social

Governance

Related Party Transactions

Subsequent Events

Parent Company

Financial Statements

Condensed Consolidated Statement of Operations

Condensed Consolidated Statement of Comprehensive Earnings

Condensed Consolidated Statement of Financial Position

Condensed Consolidated Statement of Cash Flows

Condensed Consolidated Statement of Changes in Equity

Parent Company Statement of Operations

Parent Company Statement of Changes in Equity

Notes to the Condensed Consolidated Financial Statements

1. Corporate information

2. Basis of presentation

Changes in Accounting Policies

Going Concern

3. Segment Information

4. Revenue

5. Finance Costs

6. Property, Plant and Equipment (PP&E)